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GOLDMAN SACHS ENERGY CONFERENCEJanuary 9, 2018
Forward-Looking Statements
2
This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 ("Securities Act"), Section 21E of the Securities Exchange Act of 1934 ("Exchange Act"), and the United States ("U.S.") Private Securities Litigation Reform Act of 1995 regarding our business, financial condition, results of operations, and prospects. All statements other than statements of historical fact included in and incorporated by reference into this report are "forward-looking statements". Words such as expects, anticipates, intends, plans, believes, seeks, estimates, and similar expressions or variations of such words are intended to identify forward-looking statements herein. Forward-looking statements may include, among other things, the effects of the Bayswater Exploration and activity levels on the acquired acreage; the level of non-operated well activity following the pending acreage exchanges; future reserves, production, costs, cash flows, and earnings; drilling locations and growth opportunities; capital investments and projects, including expected lateral lengths of wells, drill times and number of rigs employed; rates of return; operational enhancements and efficiencies; management of lease expiration issues; financial ratios; and midstream capacity and related curtailments.
The above statements are not the exclusive means of identifying forward-looking statements herein. Although forward-looking statements contained in this presentation reflect our good faith judgment, such statements can only be based on facts and factors currently known to us. Forward-looking statements are always subject to risks and uncertainties, and become subject to greater levels of risk and uncertainty as they address matters further into the future. Throughout this presentation or accompanying materials, we may use the terms “projection”, “outlook” or similar terms or expressions, or indicate that we have “modeled” certain future scenarios. We typically use these terms to indicate our current thoughts on possible outcomes relating to our business or the industry in periods beyond the current fiscal year. Because such statements relate to events or conditions further in the future, they are subject to increased levels of uncertainty.
Further, we urge you to carefully review and consider the cautionary statements and disclosures, specifically those under the heading "Risk Factors," made in the Quarterly Report on Form 10-Q, our Annual Report on Form 10-K for the year ended December 31, 2016 (the "2016 Form 10-K"), filed with the U.S. Securities and Exchange Commission ("SEC") on February 28, 2017, and our other filings with the SEC for further information on risks and uncertainties that could affect our business, financial condition, results of operations, and prospects, which are incorporated by this reference as though fully set forth herein. We caution you not to place undue reliance on the forward-looking statements, which speak only as of the date of this report. We undertake no obligation to update any forward-looking statements in order to reflect any event or circumstance occurring after the date of this presentation or currently unknown facts or conditions or the occurrence of unanticipated events. All forward-looking statements are qualified in their entirety by this cautionary statement.
This presentation contains certain non-GAAP financial measures. A reconciliation of each such measure to the most comparable GAAP measure is presented in the Appendix hereto. We use "adjusted cash flows from operations," "adjusted net income (loss)," "adjusted EBITDA“, and “adjusted EBITDAX” and "PV-10," non-GAAP financial measures, for internal reporting and providing guidance on future results. These measures are not measures of financial performance under GAAP. We strongly advise investors to review our financial statements and publicly filed reports in their entirety and not rely on any single financial measure. See the Appendix for a reconciliation of these measures to GAAP. Rate of return estimates do not reflect lease acquisition costs or corporate general and administrative expenses. Non-proved estimates of potentially recoverable hydrocarbons and EURs may not correspond to estimates of reserves as defined under SEC rules. Resource estimates and estimates of non-proved reserves include potentially recoverable quantities that are subject to substantially greater risk than proved reserves.
© 2018 PDC Energy, Inc. All Rights Reserved.
1/8/18
<2.0xLeverage Ratio(1)
(2017-2019)
PDC Energy – Strategic Overview
(1) Leverage Ratio is defined in revolving credit facility agreement; (2) Excludes Transportation, Gathering and Processing (TGP); (3) YE16, does not include 240 locations from Bayswater Acquisition.
~35%3-year
Production CAGR (2016-2019)
< $32017e Corporate
LOE/Boe
< $4Avg. Corporate Oil
Differentials(2)
($/Bbl)
15%Watt. Drilling
Efficiency Gains
2,600~ Drilling
Inventory(3)
Top-Tier Growth Profile
Financial Discipline
Technical Innovations
Marketing & Midstream
Shareholder Value Creation
Capital Efficient Drilling
Strategic Overview
1/8/18 3
PDC Energy – Premier Assets Provide Top-Tier Growth
(1) As of 1/3/18; assumes 65.9 mm shares outstanding; (2) YE16 – ~700 proved and ~1,100 probable, does not include 240 locations from Bayswater acquisition; (3) As of YE16 – Reflects 5,000’ laterals in Eastern and Central areas and 10,000’ laterals in Western area
~322017e Production (MMBoe)
151 2017e TILs
341YE16 Proved Reserves (MMBoe)
40+%2017e Annual Production Growth
$3.5BMarket Cap(1)
2,600~ Horizontal Locations(2,3)
Enterprise Value(1)
$4.7B
Core Wattenberg• ~95,500 net acres
• 1,800 identified locations(2)
• 305 MMBoe proved reserves
Delaware Basin• ~60,000 net acres
• 785 identified locations(3)
• 33 MMBoe proved reserves
Utica Shale
1/8/18 4
PDC Energy – Track Record of Delivering Value
~32 MMBoe22.2 MMBoe15.4 MMBoe9.3 MMBoe
0
5
10
15
2014 2015 2016 2017e
Oil Production (MMBbls)
2014 2015 2016 2017e
$0
$5
$10
$15
$20
$25
2014 2015 2016 2017e
Operating Costs ($/Boe)LOE per BOE TG&P Production Taxes G&A
1/8/18
$0
$20
$40
$60
$80
$100
0%
20%
40%
60%
80%
100%
2014 2015 2016 2017e
NYM
EX O
il ($
/Bb
l)
Gro
ss M
argi
n (
%)
Gross Margin(2)
Gross Margin NYMEX Oil
(1) Excludes fees related to Delaware Basin acquisition; (2) Gross margin is defined as oil gas and NGL sales less LOE, TGP and production tax, expressed as a percent of oil, gas and NGL sales 5
(1)
PDC Energy – Third Quarter 2017 Results
1/8/18 6(1) Leverage ratio is defined in revolving credit facility agreement
$2.98LOE/Boe
47%Year-over-Year Oil Prod. Increase
(Bbls/d)
92,500(Boe/d)
28%Delaware Production Increase
(3Q17 v 2Q17)
2017 Third Quarter Highlights
• Continued execution in Wattenberg drives strong results
─ ~77,580 Boe/d 3Q17 production
─ 46 gross operated spuds (18 SRL; 20 MRL; 8 XRL)
─ 39 TILs (14 SRL; 9 MRL; 16 XRL)
• Solid Results in Delaware program
─ ~12,845 Boe/d represents ~28% production increase (3Q17 vs 2Q17)
─ Initial enhanced completion design tests in Eastern area Wolfcamp A
─ Strong results from first Wolfcamp B wells in Eastern area
─ Continued outperformance of acquisition type curve in Central area
• Continued focus on strong financial positioning
─ Liquidity of $836 million as of September 30, 2017
─ Leverage ratio(1) improved to 1.8x
─ Robust hedge positions enable predictability of margins
PDC Energy – 2018 Production and Capital Investment Guidance
(1) Leverage ratio is defined in revolving credit facility agreement
153Spuds
~$130mmOutspend ($50 Oil/$3 Gas)
~120,000Dec. Exit Rate (Boe/d)
161TILs
Capital Investment Details(All numbers approximate)
Wattenberg ($480MM)− $425MM operated D&C
− 131 spuds & 139 TILs (85% avg. WI)− Focus in Kersey Area
Delaware ($395MM)− $275MM operated D&C
− 22 spuds & 22 TILs (90% avg. WI)− $60MM in midstream infrastructure
− $20MM for crude oil gathering− $40MM for SWDs, gas gathering lines, etc.
− $60MM in non-op, leasing, seismic and misc.
Utica− Anticipated divestiture completed in 1Q18− Proceeds not included in outspend projection
2018e Production(MMBoe)
2018e Capital Investment($ millions)
YE18e Leverage Ratio(1)
1/8/18 7
2018e Production Mix
~42%Oil
~36%Gas
~22%NGL
Robust Hedge Position Insulates Capital Program
8
CIG Basis Swaps – 4Q17: 13,264 BBtu hedged at ($0.34) off NYMEX; 2018: 35,200 BBtu hedged at ($0.36) off NYMEXWaha Basis Swaps – 2018: 6,000 BBtu hedged at ($0.50) off NYMEXEl Paso Basis Swaps – 2018: 3,000 BBtu hedged at ($0.62) off NYMEXPropane Hedges – 4Q17: 17.3 million gallons at $0.65/gallon; 2018: 44.0 million gallons at $0.76/gallon
Hedges in Place as of 9/30/17 Plus Hedges Entered Into prior to 12/31/17
1/8/18
CRUDE OIL
Q4 17 2018 2019
Volumes (MMBbls)
Collar 0.6 1.5 -
Swap 1.8 10.4 6.6
Total Crude Oil Hedged 2.5 11.9 6.6
Crude Oil Price ($/Bbl)
Floor 49.54$ 41.85$ -$
Ceilings 62.32$ 54.31$ -$
NYMEX Swap 50.13$ 52.93$ 52.47$
Weighted Average Price (floor) 49.98$ 51.52$ 52.47$
NATURAL GAS
Q4 17 2018 2019
Volumes (BBtu)
Collar 2,895 5,230 -
Swap 10,310 51,280 -
Total Natural Gas Hedged 13,205 56,510 -
Natural Gas Price ($/Mmbtu)
Floor 3.38$ 3.00$ -$
Ceilings 4.02$ 3.54$ -$
NYMEX Swap 3.39$ 2.95$ -$
Weighted Average Price (floor) 3.39$ 2.95$ -$
PDC Energy – Balance Sheet Strength and Liquidity
Leverage and Liquidity (as of 9/30/17)
• $836 million liquidity
• $136 million cash balance
• Leverage ratio(1) of 1.8x
• Borrowing base increased from $950 million to $1.1 billion in October 2017
Debt Maturities(2)
• $700 million credit facility due May 2020
• $200 million 1.125% convertible notes due Sept. 2021
• $400 million 6.125% senior notes due Sept. 2024
• $600 million 5.750% senior notes due May 2026
Corporate Ratings
• Moody’s – Upgraded to Ba3 (“Stable Outlook”) Nov. 2017
• S&P – Upgraded to BB- (“Stable Outlook”) August 2017
(1) Leverage ratio is defined in revolving credit facility agreement; (2) Debt maturities include transactions completed after 9/30/17.
$0
$250
$500
$750
$1,000
2018 2019 2020 2021 2022 2023 2024 2025 2026
Debt Maturity Schedule(millions)
Undrawn Revolver
1.125% Convertible Notes 6.125% Senior Notes
5.750% Senior Notes
1/8/18 9
ASSET OVERVIEW
Core Wattenberg – 2017 OverviewAcreage Trades Closed in November and Bolt-On Acquisition Closed in January 2018
(1) ~700 proved and ~1,100 probable locations, does not include 240 locations from Bayswater acquisition; (2) TIL = turn-in-line; SRL = standard-reach lateral, MRL = mid-reach lateral, XRL = extended-reach lateral
1332017e TILs
1552017e Spuds
305YE16 Proved Reserves (MMBoe)
7,300’Avg. 2017e TIL (Lateral Feet)
~ Net Acres
~ Acreage HBP
Horizontal Locations(1)
XRL 47%
MRL 23%
SRL 30%
2017e TIL Breakdown(2)
1/8/18 11
Wattenberg Transactions Consolidate Position – Increase XRL Development Potential
1/8/18 12
• Consolidated acreage positions favorable for XRL development
─ Kersey: ~30,000 net acres; Prairie: ~30,000 net acres; Plains: ~17,500 net acres
• Prairie acquisition expected to add ~8,300 net acres and ~2,200 Boe/d(1)
─ Adds 240 estimated gross drilling locations (~2 years of inventory at current pace)
─ Increases working interest in ~60 PDC wells
─ Includes 30 DUC wells – plan to TIL 18 (~YE17)
─ All numbers subject to ongoing due diligence
• Plains & Prairie Area EURs and commodity mix based on industry data
─ PDC completion technique not utilized in majority of data
─ Estimated development schedule – coincides with planned midstream expansion
Acreage Trades Closed in November; Bolt-On Acquisition Closed in January 2018
(1) Production at time of signing, does not include any potential production associated with DUC wells; (2) Development plan reflects current expectations
Post-Closings Acreage Map
AREA
Prairie
Plains
Kersey 1,100
1,050
600
XRL EURGross MBoe
30-34%
24-30%
40-60%
% Oil
~350
~285
~300
Oil MBbls/Well
Current
2019
2020+
Development
Core Wattenberg – Drilling Efficiencies
1/8/18 13
• Continued improvement in spud-to-spud drill times
─ SRL = 6 days
─ MRL = 8 days
─ XRL = 10 days
• Expect to spud 155 wells and TIL 133 wells in 2017
─ Original plan estimated 139 spuds and 139 TILs
─ Anticipate managing TILs in 4Q17
• Three rig program drills the same lateral feetas 3.75 rig program compared to Analyst Day
All numbers approximate SRL MRL XRL SRL MRL XRL
Lateral Length 4,200’ 6,900’ 9,500’ 4,200’ 6,900’ 9,500’
Drilling days (spud-to-spud) 7 10 12 6 8 10
FY17e Operated Spuds 50 51 38 47 62 46
Lateral Feet Drilled (000’s) 210 352 361 197 428 437
FY17e Operated TILs 50 41 48 40 31 62
12
7 76
0
5
10
15
2015 2016 1H17 2H17
Day
s
SRL
18
1110
8
0
5
10
15
20
2015 2016 1H17 2H17
Day
s
MRL
-
14
12
10
0
5
10
15
2015 2016 1H17 2H17
Day
s
XRL
2017 Analyst Day 2Q17 Earnings Call
Additional Compression 2018-2019 Processing Capacity Expansions
GrandPkwy
Plant 10
Plant 11
Kersey
Plains
Prairie
Post-Closings Acreage Map(1)
Core Wattenberg – Midstream Overview
1/8/18
NATURAL GAS
• Multiple midstream providers (DCP and Aka-APC)
─ DCP expected to gather and process ~72% of 2017e gas volumes
• DCP current capacity ~850 MMcf/d
• Working with midstream providers regarding potential additional processing/gathering capacity
OIL
• Ample takeaway capacity projected through 2020
• Minimal firm commitments enable competitive pricing opportunities
Additional Capacity Enables Future Growth Objectives
(1) Post closing of transactions announced on 9/25/17. (2) Source: DCP Midstream press release, 11/7/17
DCP Planned Expansions(2)
• + 40 MMcf/d bypass (in-service July 2017)• +200 MMcf/d plant 10 (4Q 2018)• +200 MMcf/d plant 11 (mid-year 2019)
14
Delaware Basin – 2017 Overview
(1) The Company impaired 13,400 net acres in the Western area in 3Q17.
28%Production Growth (3Q17 v 2Q17)
182017e TILs
242017e Spuds
12,8453Q17 Production (Boe/d)
~ Net Acres(1)
Average Working Interest
2017e XRL TILs
1/8/18 15
2017e Capital Investment Details
• $285 million D&C budget
─ Spud 24 wells
─ 15 spuds in Eastern
─ 7 spuds in Central
─ 2 spuds in Western
─ TIL 18 wells including 8 XRLs
• $35 million midstream infrastructure
─ Add SWD wells and capacity
─ Drill water supply well and construct frac pits
─ Install gas gathering lines
• $25 million leasing, seismic & tech studies
Well Name TIL Date
Wolfcamp
Bench
Lateral
Length
(feet)
30-day Peak IP
(Boe/d; 2-phase) % Oil
Clustered
Perf
Buzzard South 11/27/2017 B 9,805 1,641 69% Y
Buzzard North 11/20/2017 A 9,861 2,944 69% Y
Elkhead 8/25/2017 B 9,716 2,254 69% N
Blue Lakes 8/3/2017 A 9,817 1,528 49% N
Lost Saddle 5/25/2017 A 3,963 1,405 45% Y
Hermit 5/12/2017 B 9,684 1,502 18% N
Kenosha 3/7/2017 A 9,331 2,295 51% N
Argentine 12/12/2016 A 4,553 1,185 72% N
Delaware Basin – Gaining Operational Momentum
1/8/18 16
• Continued improvement in completion operations
─ Clustered perf design showing encouraging initial results
─ Increased capital efficiency from longer laterals
• 2018 TILs: 14 in Eastern Area, 11 in Block 4
─ Six well downspacing test (testing 12 wells per section equivalent spacing in Wolfcamp A)
─ Initial Wolfcamp C test planned (Grizzly West)
Recent Well Result Details
2016 - 2017 TILs2017 New TILs2018 Expected TILs
Eastern Area – Block 4
Buzzard North
Buzzard South
Elkhead
Kenosha
Argentine
Lost Saddle
Hermit
Blue Lakes
Grizzly South
Grizzly North
Grizzly West
Grizzly Bear (6 Well Downspacing Test)
Approximate Surface Locations
0
100,000
200,000
300,000
400,000
500,000
0 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450
Gro
ss C
um
ula
tive
2-P
has
e P
rod
uct
ion
per
5,0
00
' (B
oe)
Days
PDC Average (8 wells)
Type Curve +50%
Type Curve +100%
2wells3 wells4 wells5 wells6 wells8 wells
Delaware Basin – Prolific Eastern Area Wolfcamp A Well Results
1/8/18 17
• Lost Saddle well (~4,000’ lateral)
─ 1st enhanced clustered completion design
─ 30-day peak IP: 1,450 Boe/d (~363 Boe per 1,000’)
─ Production more than double 1,000 MBoe EUR type curve on cumulative basis
─ No additional cost for clustered completions
• Five TILs in Eastern area in 4Q17 (4 XRLs)
(Well Data as of 11/7/17)
(1) Based on industry activity in 2015 – 2016
Eastern Area – Wolfcamp A
0
100,000
200,000
300,000
400,000
500,000
0 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450
Gro
ss C
um
ula
tive
2-P
has
e P
rod
uct
ion
per
5,0
00
' (B
oe)
Days
Keyhole
Sugarloaf
Hanging H
Argentine
Kenosha
Blue Lakes
Gavster State
Lost Saddle
Eastern Area – Wolfcamp A
1,000 MBoe EUR AcquisitionType Curve(1)
1,000 MBoe EUR Acquisition Type Curve(1)
0
50,000
100,000
150,000
200,000
250,000
0 30 60 90 120 150 180 210 240 270 300 330 360 390 420 450
Gro
ss C
um
ula
tive
2-P
has
e P
rod
uct
ion
per
5,0
00
' (B
oe)
Days
Triangle
Hermit
Elkhead
Delaware Basin – Initial Eastern Area Wolfcamp B Well Results
1/8/18 18
• Elkhead well (~10,000’ lateral Wolfcamp B)
─ ~2,250 Boe/d last 45 days (yet to reach peak production)
─ ~1,550 bbls/d oil
─ Production profile similar to Kenosha well (10,000’ Wolfcamp A well)
• Hermit well (~10,000’ lateral) averaging ~1,500 Boe/d
─ Casing PSI of ~3,800
Early Data on Limited Sample Size as of 11/7/17
(1) Based on industry activity in 2015 – 2016
Eastern Area – Wolfcamp B
750 MBoe EUR AcquisitionType Curve(1)
1
10
100
1000
10000
0 20 40 60 80 100 120 140
Bo
e/d
Days
Kenosha Elkhead
Elkhead & Kenosha Daily Performance Comparison
0
100,000
200,000
300,000
0 60 120 180 240 300 360 420
Gro
ss C
um
ula
tive
2-P
has
e P
rod
uct
ion
per
5,0
00
' (B
oe
Days
Liam State
HSS State
Greenwich 4H
Greenwich 3H
Delaware Basin – Recent Central Area Wells Exceeding Type Curve
1/8/18 19
Central Area Well Highlights
• Liam State cumulative production on trend to outperform 1,050 MBoe EUR normalized type curve
• Greenwich 4H (Wolfcamp A)
─ Sustained outperformance of acquisition type curve
• Eight Central Area TILs planned in 2018
─ Includes three additional Greenwich wells
(Well data as of 11/7/17)
(1) Based on industry activity in 2015 – 2016
Central Area – Wolfcamp A/B
1,050 MBoe EUR AcquisitionType Curve(1)
Marketing & Midstream – Gas Throughput and Processing Overview
Eagle Claw
• Current capacity of ~520 MMcf/d
─ Planned expansion in 1/18 – incremental 200 MMcf/d
Energy Transfer (ETC)
• ETC in northern acreage of Central area (current capacity of ~1,000 MMcf/d)
─ PDC owned Westeros compressor station expansion recently completed
Western Gas (WES)
• Current capacity of ~800 MMcf/d with planned expansions at both Ramsey and Mentone facilities
Gas Delivered to Both El Paso and Waha Markets
Eastern
CentralWestern
1/8/18
Western Gas
ETC/Undedicated
Eagle Claw
3rd Party Midstream Central Delivery Points
PDC Gas Gathering
Asset YE16 17e Adds Total
Gas Gathering (miles) 60 37 97
Produced Water Pipeline (miles) 35 35 70
SWD Wells 5 3 8
Compression Facilities 5 (1) 4
Fresh Water Pits 10 3 13
Acquired Assets + 2017 Infrastructure Investment
Added 40,000 MMBtu/d firm transportation basin to Waha through 2020
20
Long-Term Delaware Midstream Vision – Roadmap to Incremental Value Creation
Long-Term: Evaluate midstream ownership options – 100% ownership, Joint Venture, potential full or partial monetization
Create separate fee structures for in-field midstream services
Crude oil gathering systems with initial focus on Eastern area
Long-Term: Evaluate potential 3rd party volumes and options to operate and/or participate in gas processing plants and related infrastructure
Fresh water supply distribution options and potential produced water recycling systems
Build out PDC midstream assets & infrastructure to support development plans – 100% PDC owned
Key Objectives
1/8/18
Key Evaluations
21
<2.0xLeverage Ratio(1)
(2017-2019)
PDC Energy – Key Takeaways
(1) Leverage Ratio is defined in revolving credit facility agreement; (2) Excludes Transportation, Gathering and Processing (TGP); (3) Well-head economics assumes base case pricing, reflects basin differentials and excludes G&A
~35%3-year
Production CAGR (2016-2019)
< $32017e Corporate
LOE/Boe
< $4Avg. Corporate Oil
Differentials(2)
($/Bbl)
15%Watt. Drilling
Efficiency Gains
2,600~ Drilling Inventory
Top-Tier Growth Profile
Financial Discipline
Technical Innovations
Marketing & Midstream
Shareholder Value Creation
Capital Efficient Drilling
Strategic Overview
1/8/18 22
Investor RelationsMike Edwards, Senior Director Investor Relations
Kyle Sourk, Manager Investor Relations
Corporate HeadquartersPDC Energy, Inc.1775 Sherman StreetSuite 3000Denver, Colorado 80203303-860-5800
Website
www.pdce.com
APPENDIX
PDC Energy – 2017 Production & Capital Guidance(Does Not Reflect Potential Effect of Wattenberg Transactions Announced on 9/25/17)
~95,000December ‘17 Exit Rate (Boe/d)
1512017e TILs
1792017e Spuds
~50%Year-Over-Year Increase in Oil Production
2017e Production MixWattenberg• Operated 3-4 rigs• ~30% annual production growth• 155 Spuds • 133 TILs with ~7,300’ avg. lateral length• 86% WI
Delaware• Operated 3-4 rigs • 24 Spuds• 18 TILs with ~7,900’ avg. lateral length• 92% WI
2017e Production (MMBoe)
Production Growth
Increase in Lateral Feet Drilled
1/8/18
~40%Oil
~37%Gas
~23%NGL
25
PDC Energy – Capital Efficiency in a $50 and $3 World
1/8/18 26
2017 - 2019: Mid-Year $50/$3 Case vs. Analyst Day Base Case:
• Based on six rig pace through 2019 compared to acceleration to 11 rigs in AD Base Case
• ~$400 million reduction in 3-year total capital spend
• Anticipate cash flow neutrality in 2019 at $50/Bbl NYMEX
• Projected YE19 Leverage Ratio of 1.1x vs 0.9x in AD Base Case
─ $50/Bbl vs $61/Bbl NYMEX in AD Base Case
• Capital efficient production growth
─ 2019e production only <5% below AD Base Case projections
─ ~35% 3-year CAGR (‘16-’19)
$50/Bbl and $3/Mcf NYMEX Prices Held Flat (Does Not Reflect Actual 2018 Production & Capital Guidance on 12/11/17)
(1) Does not include anticipated closing of previously announced Wattenberg acquisition; (2) Assumes $700 million revolving credit facility
$50/Bbl and $3/Mcf NYMEX 2017e 2018e 2019e
YE Leverage Ratio ~1.8x ~1.6x ~1.1x
Capital Investment (MM) ~$800 $850 - $900 $900 - $1,000
Outspend (Capex/Cash Flow) ~45% ~25% ~0%
YE Cash/(Revolver) (MM) $100 - $150(1) (0 – 15% drawn)(2) (0 – 15% drawn)(2)
Production Profile~32 MMBoe
(~45% YoY growth)
20 – 30% growth 30 – 40% growth
Rig Program (WB/DE) 3/3 3/3 3/3
0.0x
1.0x
2.0x
3.0x
4.0x
0
20
40
60
80
2016 2017e 2018e 2019e
Leve
rage
Rat
io
MM
Bo
e
Production and Leverage Ratio OutlookProduction Range Leverage Ratio
Kersey Area – Growing Oil Volumes
• Oil volumes per well continue to grow
• GOR typically stabilizes after 18-36 months
• MRL and XRL wells represent recent completion design improvements
─ SRL 490 MBoe EUR still based on 2015 completion design
─ SRL upside projects 600 MBoe EUR (based on % improvement similar to MRL and XRL type curves)
Based on Previous Analyst Day Type Curves
(1) Oil volumes based on EURs and % oil disclosed at previous Analyst Days
0
2
4
6
8
10
12
2014 2015 2016 2017e
Wattenberg Oil Production (MMBbls)
2015 2016 2017 2015 2016 2017 2016 2017
SRL
MRL
XRL
SRL potential upside w/ new completions
185 175160
180-200
250 245255
305
350Oil Volume per Well(1)
(MBbls)
1/8/18 27
Reconciliation of Non-U.S. GAAP Financial Measures
1/8/18 28(1) Other includes the impact of provisions for the uncollectible notes receivable in the nine months ended September 30, 2017, and the six months ended June 30, 2016.
Adjusted EBITDAX
Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Net loss to adjusted EBITDAX:
Net loss $ (292.5 ) $ (23.3 ) $ (205.1 ) $ (190.3 )
(Gain) loss on commodity derivative instruments 52.2 (19.4 ) (86.5 ) 62.3
Net settlements on commodity derivative instruments 9.6 47.7 22.2 167.9
Non-cash stock-based compensation 4.8 4.1 14.6 15.2
Interest expense, net 18.8 20.1 56.9 40.9
Income tax benefit (122.4 ) (12.0 ) (71.5 ) (112.2 )
Impairment of properties and equipment 252.7 0.9 282.5 6.1
Impairment of goodwill 75.1 — 75.1 —
Exploration, geologic, and geophysical expense 41.9 0.2 43.9 0.7
Depreciation, depletion, and amortization 125.2 112.9 360.6 317.3
Accretion of asset retirement obligations 1.5 1.8 4.9 5.4
Adjusted EBITDAX $ 166.9 $ 133.0 $ 497.6 $ 313.3
Cash from operating activities to adjusted EBITDAX:
Net cash from operating activities $ 148.2 $ 163.0 $ 411.4 $ 360.8
Interest expense, net 18.8 20.1 56.9 40.9
Amortization of debt discount and issuance costs (3.2 ) (9.9 ) (9.6 ) (13.0 )
Gain on sale of properties and equipment 0.1 0.2 0.8 —
Exploration, geologic, and geophysical expense 41.9 0.2 43.9 0.7
Exploratory dry hole (41.2 ) — (41.2 ) —
Other(1) (0.4 ) (0.2 ) 39.2 (41.5 )
Changes in assets and liabilities 2.7 (40.4 ) (3.9 ) (34.6 )
Adjusted EBITDAX $ 166.9 $ 133.0 $ 497.6 $ 313.3
Reconciliation of Non-U.S. GAAP Financial Measures
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Adjusted Cash Flows from Operations
Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Adjusted cash flows from operations:
Net cash from operating activities $ 148.2 $ 163.0 $ 411.4 $ 360.8
Changes in assets and liabilities 2.7 (40.4 ) (3.9 ) (34.6 )
Adjusted cash flows from operations $ 150.9 $ 122.6 $ 407.5 $ 326.2
Adjusted Net Income (Loss)
Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Adjusted net loss:
Net loss $ (292.5 ) $ (23.3 ) $ (205.1 ) $ (190.3 )
(Gain) loss on commodity derivative instruments 52.2 (19.4 ) (86.5 ) 62.3
Net settlements on commodity derivative instruments 9.6 47.7 22.2 167.9
Tax effect of above adjustments (23.2 ) (10.8 ) 24.0 (87.6 )
Adjusted net loss $ (253.9 ) $ (5.8 ) $ (245.4 ) $ (47.7 )
Weighted-average diluted shares outstanding 65.9 48.8 65.8 45.7
Adjusted diluted earnings per share $ (3.85 ) $ (0.12 ) $ (3.73 ) $ (1.04 )
